Charge based stimulation of adjacent wells to form interconnected fracture network and hydrocarbon production therefrom

ABSTRACT

Recovering hydrocarbons from a subterranean formation includes drilling first and second adjacent wells and detonating charges in each thereby causing fractures in the subterranean formation to extend from each well and interconnect in a fracture network. The charge detonations may include charges separated by delay units to create a pulse train at a resonant frequency of the subterranean formation. Sensors may be positioned within one or more of the wellbores and the surface, and the pulse train may be detected by the sensors to ensure the fracture network between the adjacent wellbores is sufficiently interconnected. The adjacent wells may be parallel to each other and separated by an optimal separation distance determined by testing different sections of test wellbores that diverge from an intersection point at a known angle. The charges may be propellant based. Fluids/gases may be injected into injection wells and production performed from interconnected production wells.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority of U.S. ProvisionalApplication No. 62/482,591 filed Apr. 6, 2017 and U.S. ProvisionalApplication No. 62/505,454 filed May 12, 2017. Each of theseapplications is incorporated herein by reference.

BACKGROUND OF THE INVENTION (1) Field of the Invention

The invention pertains generally to recovering hydrocarbons fromsubterranean wells. More specifically, the invention relates to a methodof utilizing propellant and/or explosives to establish communication byincreasing the fracture face area between parallel wellbores or insingle wells to thereby improve well production.

(2) Description of the Related Art

Hydraulic fracturing is a known method of stimulating wells. Vastvolumes of fracking fluid such as water, chemicals and sand are pumpedat high pressure into the wellbore to overcome the tensile strength ofthe surrounding rock. As the pressure builds, fractures are createdextending outward from the wellbore. Sand or other proppants included inthe fluid enter the fractures and hold the fractures open after thepressure is reduced.

FIG. 1 illustrates an isometric view of a typical hydraulic drillingsite containing a plurality of wells 100, 110, 120. Each well 100, 110,120 includes a plurality of bi-wing fractures 102, 112, 122 extendingradially outward from horizontally orientated wellbores 104, 114, 124.FIG. 2 illustrates a top down view of a horizontal wellbore 104 of FIG.1 and its associated bi-wing fractures 102.

Although effective, hydraulic fracturing suffers from a number ofproblems. For one, not all fractures 102, 112, 122 are effective atproducing hydrocarbons, especially in rock with low permeability.Typically, up to thirty percent or more of fractures 102, 112, 122 in ashale field do not contribute to increased hydrocarbon recovery. Flowdepletion is another problem where a well 100, 110, 120 will start at ahigh flow rate and then quickly taper off. For instance, after one totwo years of starting production, production flow rate may havedecreased by eighty percent or higher. Pollution is another concern.With the pumping of millions of gallons of water combined with variouschemicals and proppants into the ground, environmentalists are concernedthat this fracking fluid will make its way to the surface andcontaminate ground water reservoirs. Propellant based stimulationutilizing a horizontal stimulation tool (HST) or the StimGun® or anotherpropellant tool assembly (PTA) is an alternative technique for creatingfractures without using large amounts of fracking fluid. PTA involvesdetonating/deflagrating combustible charges and propellants within thewellbore such that radially extending fractures (including “off plane”fractures) are created therefrom. For example, FIG. 22 illustrates aplurality of propellant charge sections ready for installation, FIG. 23illustrates a propellant charge section being loaded into an assembly,and FIG. 24 illustrates a plurality of propellant charge assemblies(PTAs) ready for installation into a wellbore. However, PTA techniquescreate fractures that are shorter in length than those created byhydraulic fracturing. Shorter length fractures are fine for productionin higher permeability rock but are not ideal for use in lowpermeability environments such as shale fields.

BRIEF SUMMARY OF THE INVENTION

In hydraulic fracturing, production is limited by restricted rock facearea for production along with rapid depletion of reservoir pressure.The low rates of fracture effectiveness and rapid depletion of ahydraulically fracked well result in inefficient reservoir utilization.An object of some embodiments of the present invention is therefore toincrease the exposed sand face area and fracture effectiveness bycreating a network of interconnected fractures between adjacentwellbores or in single wells.

An object of some embodiments of the present invention is to increaseefficiency of shale field hydrocarbon production while reducing oreliminating the volume of fracking fluids that need to be pumped in tothe ground.

An object of some embodiments of the present invention is to map thesubterranean features and ensure fracture interconnections by providingsensors in one or more well(s) adjacent to a well in which charge blastsare being detonated.

An object of some embodiments of the present invention is to map thesubterranean features and ensure fracture interconnections by detonatinga plurality of charge blasts in a wellbore at a predetermined frequencythereby creating an impulse train for detection by one or more surfaceand/or in-well sensors in adjacent well(s).

An object of some embodiments of the present invention is to increasefracture distance and volumes by detonating a plurality of charge blastsin a wellbore at a predetermined frequency selected according tocharacteristics of the subterranean formation in which the wellbore islocated.

An object of some embodiments of the present invention is to reduce welldepletion by injecting production facilitators into a first well andrecovering hydrocarbons from adjacently interconnected wells or fromother sections of the first well.

An object of some embodiments of the present invention is to usefrequency enhanced fracture growth so that propellant created multipleradial fracture creation is much more extensive and more efficient.

An object of some embodiments of the present invention is todetonate/deflagrate at resonant frequency in order initiate/enhance offplane fracturing. Multiple fracturing is easier and more efficient.

According to an exemplary embodiment of the invention there is discloseda method of recovering hydrocarbons from a subterranean formation. Themethod includes drilling a first well, drilling a second well adjacentto the first well, and detonating a first charge in the first wellthereby causing first fractures in the subterranean formation to extendfrom the first well toward the second well. The method further includesdetonating a second charge in the second well thereby causing secondfractures in the subterranean formation to extend from the second welltoward the first well, ensuring that at least some of the firstfractures interconnect with at least some of the second fractures, andrecovering hydrocarbons from at least one of the first well and thesecond well.

According to an exemplary embodiment of the invention there is discloseda method of recovering hydrocarbons from a subterranean formation. Themethod includes drilling a first well, drilling a second well adjacentto the first well, creating a plurality of first fractures extendingfrom the first well and creating a plurality of second fracturesextending from the first well. The method further comprises ensuringthat at least some of the first fractures interconnect with at leastsome of the second fractures, and recovering hydrocarbons from at leastone of the first well and the second well.

These and other advantages and embodiments of the present invention willno doubt become apparent to those of ordinary skill in the art afterreading the following detailed description of preferred embodimentsillustrated in the various figures and drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in greater detail with reference to theaccompanying drawings which represent preferred embodiments thereof:

FIG. 1 illustrates an isometric view of a typical hydraulic drillingsite containing a plurality of horizontal wellbores.

FIG. 2 illustrates a top down view of a horizontal wellbore of FIG. 1and its associated bi-wing fractures.

FIG. 3 illustrates an isometric view of a horizontal drilling sitelayout containing a plurality of adjacently located wells withinterconnected fracture networks according an exemplary embodiment ofthe present invention.

FIG. 4 illustrates a top down view of the horizontal wellbores of FIG. 3and their associated interconnected fracture networks.

FIG. 5 illustrates a top down view of a plurality of sensors in a firstwellbore for detecting sufficiency of fracture interconnection of afracture network with a second wellbore after detonating a plurality ofcharges in the second wellbore according to an exemplary embodiment.

FIG. 6 illustrates the view of FIG. 5 after the charges have beendetonated and the fractures extending from the second wellbore towardthe first wellbore have been created.

FIG. 7 shows a flowchart of a method of drilling and charge basedstimulation of adjacent wells to form an interconnected fracture networktherebetween according to an exemplary embodiment.

FIG. 8 shows a flowchart of a method of producing hydrocarbons from aplurality of wellbores having interconnected fracture networkstherebetween according to an exemplary embodiment.

FIGS. 9-16 illustrate a plurality of sequential screenshots of acomputer simulation for predicting effectiveness of charge intensity anddelay units in a particular wellbore according to an exemplaryembodiment.

FIG. 17 illustrates a side view of two wells having parallel horizontalwellbores prior to detonating a plurality of charges in a bottom one ofthe wellbores to create a fracture network according to an exemplaryembodiment.

FIG. 18 illustrates the wells of FIG. 17 after the charges have beendetonated.

FIG. 19 illustrates a plurality of vertical wellbores havinginterconnected fracture networks therebetween according to an exemplaryembodiment.

FIG. 20 illustrates a plurality of horizontal wellbores in a gun barrelcylinder configuration each having fractures radially extending in alldirections around the axle length of the wellbores to form aninterconnected fracture network according to an exemplary embodiment.

FIG. 21 illustrates additional screenshots from the computer simulationfor a working region of about 500 ft of the horizontal stimulation toolthat may be utilized in conjunction with exemplary embodiments of thepresent invention.

FIG. 22 illustrates a plurality of propellant charge sections ready forinstallation according to the prior art.

FIG. 23 illustrates a propellant charge section of FIG. 22 being loadedinto an assembly.

FIG. 24 illustrates a plurality of propellant charge assemblies (PTAs)loaded and ready for installation into a wellbore according to the priorart.

FIG. 25 illustrates a plurality of horizontal wellbores each havingfractures radially extending in all directions around the axle length ofthe wellbores to form an interconnected fracture network takingadvantage of permeability of the subterranean formation according to anexemplary embodiment.

FIG. 26 illustrates wellbore pressure changing over time during a timedignition according to an exemplary embodiment.

FIG. 27 illustrates a plan view of two adjacent horizontal wellboreshaving an angle A between their bore directions according to anexemplary embodiment.

FIG. 28 illustrates a projection view of a plurality of a plurality ofadjacent horizontal wellbores having an angle between their boredirections according to an exemplary embodiment.

DETAILED DESCRIPTION

FIG. 3 illustrates an isometric view of a horizontal drilling sitelayout containing a plurality of adjacently located wells 300, 310, 320according an exemplary embodiment of the present invention. Each well300, 310, 320 includes a plurality of bi-wing and/or radial fractures302, 312, 322 extending radially outward from horizontally orientatedwellbores 304, 314, 324. Unlike the layout of the hydraulic drillingsite of FIG. 1, in FIG. 3 the wellbores 304, 314, 324 are drilled closertogether such that the intermediate fractures 302, 312, 322 between thewellbores 304, 314, 324 interconnect with each other and create fracturenetworks 306, 316. The number of intersecting fractures and intrafracture communication is maximized by shortening the distance betweenbi-wing fractures 302, 312, 322 from each wellbore 304, 314, 324 suchthat more fractures extend radially from each wellbore 304, 314, 324 forunit distance than do for a similar distance along the wellbores 104,114, 124 of FIG. 1. In this way, the layout of the drilling site of FIG.3 is compressed in area in comparison assuming a same number ofwellbores 304, 314, 324 and bi-wing fractures 302, 312, 321 are created.Alternatively, the same area can be covered by the layout of FIG. 3 byincreasing both the number of wellbores 304, 314, 324 and the number ofbi-wing fractures 302, 312, 321 extending from each wellbore 304, 314,324.

FIG. 4 illustrates a top down view of the horizontal wellbores 304, 314,324 of FIG. 3 and their associated interconnected fracture networks 306,316. As illustrated, the fractures 302 extending outward from a firstwellbore 304 interconnect with counterpart fractures extending outwardfrom a second, adjacent wellbore 314. In this example, the firstwellbore 304 and the second wellbore 314 run parallel to each otherthrough a target subterranean formation such as a shale field. Fractures302, 312 are created along an adjacent length of each of the first andsecond wellbores 304, 314. The fractures 302, 312 extend outward fromeach wellbore 304, 314 toward the other of the first and secondwellbores 304, 314. Between the two wellbores 304, 314 a firstinterconnected fracture network 306 is created. The fracture network 306is interconnected meaning that a plurality of the respective fractures302, 312 from each wellbore 304, 314 are communicatively coupled suchthat pressure changes in a first of the wellbores 304, 314 will causepressure changes in the other of the wellbores 304, 314 and vice versa.

In this example, the second wellbore 314 and a third wellbore 324 alsorun parallel to each other through the target subterranean formation.Fractures 312, 322 are created along a similar adjacent length of eachof the second and third wellbores 314, 324 and extend outward from eachtoward the other of the second and third wellbores 314, 324. Between thetwo wellbores 314, 324, a second interconnected fracture network 316 iscreated. Again, the second fracture network 316 is interconnectedmeaning that a plurality of respective fractures 312, 314 arecommunicatively coupled such that pressure changes transfer from thesecond wellbore 314 to the third wellbore 324 and vice versa.

FIG. 5 illustrates a top down view of a plurality of sensors 500 in afirst wellbore 304 for detecting sufficiency of fracture interconnectionof a fracture network 306 with a second wellbore 314 after detonating aplurality of charges 502 in a second wellbore 314. The view of FIG. 5 istaken after a plurality of fractures 302 have already been createdextending radially from the first wellbore 304 toward the secondwellbore 314. The fractures 312 of the second wellbore 314 will becreated after the charges 502 in the second wellbore 314 are detonated.During the detonation process, the sensors 500 in the first wellboredetect changes in various attributes measured by the sensors 500 as aresult of fracture interconnections within fracture network 306.

In some embodiments, the in-well sensors 500 include pressure sensors.At the time illustrated in FIG. 5 prior to the detonation of the charges502 and prior to the creation of the fractures 312 extending from thesecond wellbore 314, the sensors 500 will not detect any pressurechanges within the first wellbore 304 caused by pressure changes in thesecond wellbore 314. This is because the existing fractures 302extending from the first wellbore 304 do not reach the second wellbore314 and the first wellbore 304 is therefore not in communication withthe second wellbore 314.

FIG. 6 illustrates the view of FIG. 5 after the charges 502 have beendetonated and the fractures 312 extending from the second wellbore 314toward the first wellbore 304 have been created. As illustrated, thefirst wellbore 304 is now in communication with the second wellbore 314via the interconnected fracture network 306.

During the detonation of the charges 502, the sensors 500 will begin todetect pressure changes as soon as the newly forming fractures 312extending from the second wellbore 314 interconnect with the previouslyexisting fractures 302 extending from the first wellbore 304. Pressuredata captured by the sensors 500 may therefore be utilized to confirmthe sufficiency of the interconnections within the fracture network 306.For example, if no pressure changes (or minimal pressure changes) aredetected by the sensors 500 during and immediately after the detonationof charges 502, this indicates that the fracture network 306 is notsufficiently interconnected. Larger intensity charges 502 may need to beemployed in this case in order to ensure the first and second fractures302, 312 extend far enough into the fracture network 306 to ensureproper wellbore communication.

In addition to pressure sensors, the in-well sensors 500 may includeother types of sensors such as seismic sensors and/or electricalsensors. Seismic sensors in particular may be beneficial to generatethree dimensional (3D) maps and gather other data about the varioussubterranean rock layer formations between the first wellbore 304 andthe second wellbore 314. As illustrated in FIG. 5, a plurality ofcharges 502 may be connected in series with a corresponding plurality ofdelay units 504 interspaced therebetween. The charges 502 may be aplurality of propellant, PTA, HST, StimGun®, and/or other any otherdesired explosive or propellant sections with millisecond delay devicesacting as delay units 504 between each charge section 502. The delayunits 504 each add a predetermined delay time before causing the nextcharge section 502 to detonate. For example, in the case where onethousand charges 502 are interconnected in series along the wellbore 314and are separated by a one millisecond delay unit, the detonation of thecharges 502 will cause a one kilohertz 1KHz pulse train to be generatedalong the length of the wellbore 314. In some embodiments, at least tenseparate charge sections 502 are coupled in series and detonated atslightly different times (e.g., on the order of millisecond delays) inorder to provide a pulse train long enough for seismic analysis.

The pulse train caused by detonating the series of charges 502 aredetected by each of the in-well seismic sensors 500 in the firstwellbore 304 and data representing the detected seismic vibrations istransmitted back to the surface. Since the position of each chargesection 502 and its respective detonation time are known in advance,information regarding the subterranean formation between the firstwellbore 304 and the second wellbore 314 can be determined according tothe seismic data. Likewise, a plurality of surface sensors 1700 (seeFIG. 17), may also detect the pulse train generated by detonating thecharges 502, and the data captured by the surface sensors 1700 can beutilized to determine information regarding the various subterraneanlayers between the surface and the second wellbore 314. This is similarto existing methods of utilizing spaced out surface charges and surfacesensors in order to determine characteristics of subterranean formationsaccording to bounce vibrations detected back at the surface. However, inthe method described herein, either the sensors 500 and/or the charges502 may be located within respective wellbores 304, 314, 324. As methodsof generating 3D maps and determining characteristics of subterraneanformations according to seismic data are well-known in the art, furtherexplanation of specific calculations is omitted herein for brevity.

In some applications, the delay value associated with the delay units504 may be selected in advance according to a type of the subterraneanformation in which fractures 312 are desired to be created. Forinstance, different types of rock layers have different naturalresonance frequencies at which they are easier to vibrate. At thesefrequencies, the rock's tensile strength may be reduced and fractureseasier to create. If the frequency of the pulse train is adjusted to bewithin a threshold range of the rock's natural resonance frequency, thefractures 312 created by the charge detonation may extend further thanthey otherwise would. In other words, through experimentation of chargedetonation with different delay times between charges in order to createimpulse trains of different frequencies, it may be determined thatcertain delay times between charge pulses achieves a more extensive andbetter interconnected fracture network 306. Fracture efficiency maythereby be increased by selecting appropriate delay units 504 between aplurality of charges 502 according to the subterranean formation type.

A predicted resonant frequency of the surrounding material may also bedetermined utilizing other methods and then charge detonations atfrequencies near the predicted resonant frequency may be tried. Forinstance, adding energy to a system will cause the material of thesystem to vibrate at the resonant frequency. Because resonant frequencymay change slightly over time or as the material changes in structuresuch as fractures are formed, the charge delays may also be set in someembodiments such that the detonation pulse train will have a slightlychanging frequency in order to follow or more closely match the actualresonant frequency of the surrounding subterranean formation material.Taking shale with a predicted natural resonance frequency of 1 kHz as anexample, the delay units 504 may be adjusted such that the chargesections 502 are detonated and form a detonation pulse train frequencysweeping from 0.9 kHz to 1.1 kHz. The delay unit 504 timings may bepre-set in advance or dynamically adjusted by one or more computerprocessors during the charge sequence detonation according to sensor 500feedback.

FIG. 7 shows a flowchart of a method of drilling and charge basedstimulation of adjacent wells to form an interconnected fracture networktherebetween according to an exemplary embodiment. The steps of theflowchart of FIG. 7 are not restricted to the exact order shown, and, inother configurations, shown steps may be omitted or other intermediatesteps added. In this embodiment, the drilling and stimulation processincludes the following steps:

A drilling and stimulation phase of operations begins at step 700. Thismay occur when starting to drill a first well or may occur when addingan additional well to a group of already-drilled wells.

At step 702, an initial well is drilled. For example, with reference toFIG. 3, the initial well drilled at this step may be the first well 300.As illustrated in FIG. 3, the initial well 300 may include a horizontalwellbore 304 drilled through a target subterranean rock formation suchas a shale field from which hydrocarbons are to be recovered.

At step 704, charges 502 and their associated delay units 504 arecalculated according to simulation data representing the type ofsubterranean formation. For example, during the drilling process of step702, data may be gathered representing the subterranean formation.Simulation parameters are updated according to all known data in orderto simulate what charge intensities and delay values will optimize thefracture lengths and numbers.

At step 706, a series of charge sections 502 interconnected by delayunits 504 according to the values calculated at step 704 are set withinthe initial wellbore 304. The charges may be set within any desired toolfor charge deployment including HST and StimGun® tools or any otherpropellant tool assembly (PTA) or explosive charge. The enclosure pipecasing (if used) may include holes in any desired patterns to causefractures to extend outward in said patterns. Bi-wing, off-planefractures, or any desired charge direction and shape may be utilized indifferent embodiments. For instance, the prior art casing on PTAassemblies of FIG. 24 will create fractures radiating in all directions.Other user-selectable values may also be calculated or estimated at thisstep in a similar manner including wellbore fluid types and amounts.

At step 708, surface sensors 1700 are placed in order to detect thepulse train generated by detonation of the plurality of charges 502 setat step 706.

At step 710, the series of charge sections 502 set at step 706 aredetonated within the initial wellbore 304 to create fractures 302extending outward from the initial wellbore 304.

At step 712, the sensor data is reviewed in order to evaluate rocklayers around the subterranean formation and in an attempt to determinethe distance and coverage of the fractures 302. Other data may also becollected at this step such as to determine whether a desired level offlow capacity is present within the wellbore 304 after the fractures 302are created.

At step 714, a determination is made as to whether the initial fractures302 and subterranean formation are as expected. For instance, if littleflow capacity is detected, the fractures 302 are found to extend lessthan an expected distance, and/or the subterranean rock layers aredifferent than expected, these negative results may mean that thesimulation parameters need to be updated to better reflect the actualsituation. Control proceeds to step 716 in this case. On the other hand,if everything is as expected, control proceeds to step 718 to start workon drilling a next well.

At step 716, the simulation parameters are updated according to thesensor data collected at step 712. Control then returns to step 704 tocalculate a better intensity of charges 502 and/or time delays of thedelay units 504 to hopefully get better fracture efficiency on asubsequent attempt at detonation.

At step 718, a next well is drilled adjacent to the initial well. Forexample, the next well may be the second well 310 shown in FIG. 3including its horizontal wellbore 314 portion running parallel to thehorizontal wellbore 304 of the initial well 300. The distance of thenewly drilled wellbore 314 from the initial wellbore 304 should be lessthan double the typical length of the fractures 302, 312 from theirrespective wellbores 304, 314. For instance, if the simulation resultsand sensor data reviewed at step 712 indicate that the initial fractures302 are extending on average about eighty feet from the initial wellbore304, the new wellbore 314 should be less than one hundred and sixty feetfrom the initial wellbore 304. In this way, assuming the new fractures312 extend about the same distance (i.e., on average eighty feet in thisexample), the new fractures 312 and the initial fractures 302 will havean overlapping portion where interconnection/cross fracture flow canoccur. Depending on rock formations, it is expected that new wellbores314 will be drilled a distance apart from one another in a range fromone hundred to five hundred feet apart, which would accommodatefractures and/or cross fracture flow extending about fifty to twohundred and fifty feet. However, the distance of the new wellbore 314from the adjacent wellbore(s) 302, 324 can be determined and adjusted ona site by site basis according to the actual fracture distances andinterconnections predicted according to simulations and/or achieved inactual experimentation.

At step 720, charges 502 and their associated delay units 504 along withpossible changes to wellbore fluid types and amounts are calculatedaccording to the simulation data. This step is similar to step 704;however, the simulation data parameters may now be verified to be withina threshold desired accuracy as a result of determining how closely theprevious simulated results matched actual results at step 714.

At step 722, a series of charge sections 502 interconnected by delayunits 504 according to the values calculated at step 720 are set withinthe newly drilled wellbore 314.

At step 724, surface sensors 1700 are again placed in order to detectthe pulse train generated by detonation of the plurality of charges 502set in the new wellbore 314 at step 722.

At step 726, in-well sensors 500 are placed within the previouslydrilled adjacent wellbore(s) such as the initial wellbore 304 forexample. In some embodiments, the sensors 500 are placed in one or moreadjacent wellbores 304 that already have fractures 302 extending towardthe newly drilled wellbore 314. In this way, the in-well sensors 500 canbe utilized to detect sufficiency of the interconnection between theseadjacent wellbores 304, 314 after detonation of the charges 502. Thein-well sensors 500 may include a plurality of different types ofsensors such as pressure sensors and seismic sensors as desired tocollect different types of data. In this way, the in-well sensors 500can detect pressure or other changes within the initial wellbore 304upon detonating charges in the new wellbore 314.

At step 728, the series of charge sections 502 set at step 722 aredetonated within the new wellbore 314 in order to create fractures 314extending outward from the new wellbore 314 toward the one or moreadjacent wellbores 304, 324.

At step 730, the sensor data is reviewed in order to evaluate rocklayers around the subterranean formation and between the adjacentwellbores 304, 314, and to determine the sufficiency of interconnectionbetween the fractures 302, 312 of these wellbores 304, 314. Other datamay also be collected at this step including determining whether adesired level of flow capacity is present within any one of more of theadjacent wellbores 304, 314 after the fractures 302, 312 are incommunication with each other.

At step 732, a determination is made as to whether the initial fractures302 and the newly formed fractures 312 are sufficiently interconnected.Sufficiently interconnected means that cross wellbore flow achievedbetween adjacent wellbores 304, 314 is greater than a predeterminedthreshold. For instance, if the in-well sensors 500 do not detect anypressure changes in the initial wellbore 304 when detonating the charges502 in the second wellbore 314, these negative results may mean that thesimulation parameters need to be updated to better reflect the actualsituation. Control proceeds to step 734 in this case. On the other hand,if everything is as expected and interconnection of fracture network 306has been confirmed such as by positive changes in pressure data detectedby the in-well sensors 500, control proceeds to step 736 to determinewhether work on drilling a next well should be performed.

At step 734, the simulation parameters are updated according to thesensor data collected at step 730. Control then returns to step 720 tocalculate a better intensity of charges 502 and/or time delays of thedelay units 504 to hopefully get better fracture efficiency andinterconnection of the fracture network 306 on a subsequent attempt atdetonation.

At step 736, a determination is made of whether there are any moreadjacent wells to drill. For instance, after finishing drilling thesecond wellbore 314 and ensuring the fracture network 306 between thefirst wellbore 304 and the second wellbore 314 is sufficientlyinterconnected, work may begin on the third well 320 and its parallelrunning horizontal wellbore 324. When work is to continue on a newadjacent well, control returns back to step 718. The loop of step 718 tostep 736 can repeat as many times as necessary to build as manyinterconnected wellbores 304, 314, 324 as desired. Likewise, any numberof interconnected fracture networks 306, 316 can be formed between theplurality of wellbores 304, 314, 324. Although only three wellbores 306,316, 324 and two interconnected fracture networks 306, 316 are shown inthe attached figures, this is for simplicity of explanation and it is tobe understood that these numbers may be increased in actual fielddeployments.

Once the desired number of wellbores 306, 316, 324 and interconnectedfracture networks 306, 316 therebetween are completed, control proceedsfrom step 736 to step 738 to end the drilling and stimulation phase.

At step 738, the drilling and stimulation phase is now complete and oneor more production phases may be started.

FIG. 8 shows a flowchart of a method of producing hydrocarbons from aplurality of wellbores having interconnected fracture networkstherebetween according to an exemplary embodiment. The steps of theflowchart of FIG. 8 are not restricted to the exact order shown, and, inother configurations, shown steps may be omitted or other intermediatesteps added. In this embodiment, the production process includes thefollowing steps:

The production phase of operations begins at step 800. In someembodiments, this step occurs anytime after the completion of step 738of FIG. 7.

At step 802, the plurality of wells 300, 310, 320 are partitioned intotwo different groups: injection wells and production wells. For example,assuming three wells 300, 310, 320 as illustrated in FIG. 3, the middlewell 310 may be selected as an injection well and the two adjacent wells300, 320 on either side may be selected as production wells. Injectionwells such as middle well 310 may be selected due to their centrallocation and high connectivity via their fracture network(s) 306, 316with adjacent production wells 300, 320.

At step 804, an injection process is started by beginning to pump fluidsand/or gases into the one or more injection well(s) selected at step802. Again, taking the example shown in FIG. 3 and assuming the middlewell 310 is selected as the injection well, fluids/gases such asmethane, salt water, carbon dioxide, solvents, etc. are pumped in to theinjection well 310.

At step 806, the fluids and/or gases injected into the injection well314 at step 804 travel through the interconnected fracture networks 306,316 toward the production wellbores 304, 324. This causes pressure to bemaintained within the production wellbores 304, 324 to facilitateproduction. Because the wellbores 304, 314, 324 are interconnected viatheir fracture networks 306, 316, the fluid injection is continued on anongoing basis during production to keep pressure on the fractures 302,312, 314 and help hydrocarbons within these fractures 302, 312, 314 maketheir way back to the one or more production wellbores 304, 314. Thecontinuous fluid injection helps prevent the rapid depletion phenomenonexperienced in typical hydraulically fractured wells such as that shownin FIG. 1. The fluids may also be designed to act as solvents toincrease mobility of hydrocarbons in place increasing production ratesand ultimate total production.

At step 808, hydrocarbons are recovered from the one or more productionwellbore(s) 304, 324.

Normal production techniques may be employed at this step so a detaileddescription is omitted herein for brevity. However, it is worthwhile tonote that feedback from the production wells 300, 320 can be utilized tocontrol the fluid injection at the injection well(s) 300. For instance,if production flow rate begins to dip, then injection flow rate may becorrespondingly increased. Again, dynamically changing the fluidinjection rates at step 804 according to production flow rates at step808 helps prevent the rapid depletion phenomenon experienced in typicalhydraulically fractures wells such as that shown in FIG. 1.

At step 810, a determination is made as to whether production isfinished. This step may be performed in any desired manner, buttypically will involve determining whether the level of hydrocarbonscurrently being recovered is sufficient to warrant continued production.Once production is finished, control proceeds to step 812; otherwise,control returns to step 808 to continue recovering hydrocarbons from theproduction well(s) 300, 320.

At step 812, fluid injection into the injection well(s) 310 is stopped.

At step 814, hydrocarbon production from the production well(s) 300, 320is stopped. In order to claim any residual hydrocarbons left in thewells 300, 310, 320, this step may be performed a predetermined timeduration after injection fluids are stopped at step 812.

At step 816, the production phase is finished.

After step 818, clean up and reclamation procedures may begin. However,in some embodiments, the production process of FIG. 8 may be restartedand different selection of injection wells and production wells may beperformed at step 802. Repeating the production process with differentinjection and production wells may be beneficial to ensure that allrecoverable hydrocarbons are produced from the wells 300, 310, 320.Likewise, additional wellbores may be drilled and additional fracturenetworks created by returning to step 718 of FIG. 7.

Simultaneous execution of drilling, stimulation, injection, andproduction steps in FIG. 7 and FIG. 8 may also take place in otherembodiments. For instance, after drilling and stimulation is completedfor a first two wells, injection and/or production may begin on thosetwo wells while drilling and stimulation work continues to formadditional interconnected wells. The injection process maintainspressure as the fractures of the new wells interconnect with existingfracture networks and create new fracture networks. Additionally,because the plurality of wells are interconnected and in communicationvia their fracture networks, even if some hydrocarbons flow out ofexisting production wells into newly drilled wells, these hydrocarbonswill eventually be recovered when production starts on the new wells. Insome embodiments, a plurality of wells are simultaneously drilled andthen simultaneous stimulation is performed on each.

FIGS. 9-16 illustrate screenshots of a computer simulation forpredicting effectiveness of charge 502 intensity and delay units 504 ina particular wellbore 304, 314, 324 according to an exemplaryembodiment. The computer simulation screenshots in the examples of FIGS.9-16 were performed utilizing a dynamic event modeling computer softwareprogram called PulsFrac™ by Baker Hughes. However, it should be notedthat any desired propellant tool assembly simulation program may beutilized in other applications.

FIG. 9 shows a first screenshot of the computer simulation prior tobeginning the charge detonation. The simulation output is generallydivided into three graphical rows: a top row 900 shows a plurality ofcharges on a stimulation tool string located within a wellbore, a middlerow 902 shows the pressure within the wellbore, and a bottom row 904shows the fluid velocity within the wellbore. The legend 906 on theright-hand side from top to bottom indicates the colors for the variousdata that will be displayed during the simulation. In particular, thedata indicating pressure includes the following measurable elements:

TABLE 1 Pressure data Tool Tool gas 910 Interior Tool gas 912 Air 914KCI water 916 Light oil 918 Annulus 1 Tool gas 920 Air 922 KCI water 924Light oil 926

Likewise, the data indicating fluid velocity for the bottom row 904includes the following elements:

-   -   Tool 928    -   Interior 930    -   Annulus 1 932

After inputting the various simulation parameters, the play/run button908 is pressed to start the simulation.

FIG. 10 illustrates a second screenshot of the computer simulation afterthe charge detonation simulation is started. As illustrated in themiddle pressure row 902, the interior pressure 914 immediately begins toincrease. Likewise, as shown in the bottom fluid velocity row 904, theinterior 930 begins to drop and the tool 928 begins to rise.

FIG. 11 illustrates a third screenshot of the computer simulation whilethe charge detonation simulation continues from that shown in FIG. 10.As illustrated, the interior tool gas 912 and annulus 1 air 922 continueto rise. Fluid pressures of each of the tool 928, interior 930, andannulus 932 are changing.

FIG. 12 illustrates a fourth screenshot of the computer simulation whilethe charge detonation simulation continues from that shown in FIG. 11.At this point several of the charges 502 have been detonated.

FIG. 13 illustrates a fifth screenshot of the computer simulation whilethe charge detonation simulation continues from that shown in FIG. 12.At this point the last of the charges 502 is about to be detonated.

FIG. 14 illustrates a fifth screenshot of the computer simulation whilethe charge detonation simulation continues from that shown in FIG. 13.At this point all charges 502 have been fired and the pressures arebeginning to stabilize while the fluid velocities are still highlyturbulent.

FIG. 15 illustrates a fifth screenshot of the computer simulation whilethe charge detonation simulation continues from that shown in FIG. 14.At this point the fluid velocities are beginning to stabilize.

FIG. 16 illustrates a fifth screenshot of the computer simulation whilethe charge detonation simulation continues from that shown in FIG. 15.The simulation is about to end and both the pressures and the fluidvelocities have stabilized.

Tool gas 920 refers to the middle graphic row 902 and illustrates thetool gas pressure resulting from the combustion developed during theburn. The tool gas 910 and the air 922 in the middle graphic row 902refer to the pressure of the fluids in the wellbore, the lighter shadedtool gas 910 the water commonly used to fill the hole before the job andthe black air 922 is formation fluid surrounding the tool beforeignition.

It should be noted that the animation format illustrated in FIGS. 9-16is set up to handle several different scenarios. Different scenarios maynot employ all the measurable elements in the legend 906. Likewise, themeasurable in the legend 906 may actually refer to a differentmeasurable than is labeled in the legend as is normal behavior of thesimulation software package. For example, in the illustrated example,air 914 in the interior as labeled in the legend 906 actually refers tointerior fluid since there is no air for this type of tool. Similarly,the light oil 918 measurable in the legend 906 is unused in the aboveillustrated examples but can be used in other types of tools andsimulations.

FIG. 21 illustrates additional screenshots from the computer simulationfor a working region 2106 of about 500 ft (from 7500 ft to 8000 ft) ofthe horizontal stimulation tool 2108. Again, the computer simulationscreenshot in the example of FIG. 21 is performed utilizing thePulsFrac™ software by Baker Hughes; however, any desired simulationtool/software may be employed in other examples. As shown, thepropellant weight starts off about 2400 lbs and achieves fractures ofapproximately 150 ft.

Parameters that were inputted into the simulation according to the siteformation features include:

Formation Type: Shale Permeability: 0.01md Porosity: 0.01 Fluid Type:KCI Water Density: 1.01 g/cm{circumflex over ( )}3 Sound Speed: 5000ft/s Existing Perfs Top: na Bottom: na Hole Density: na Tool(Multi-Tool) Type: HST Propellant (Multi- Diameter: 3.0 in Tool)Loading: na Perf Gun (Multi-Tool) Diameter: na Hole Density: na Phasing:na

Key information for the working region 2106 include:

Propellant Length: 490.0 ft Peak Pressure: 9257 psi Min Pressure: 2940psi Frac Length Max: 146.79 ft

Concerning the simulation data that is utilized to calculate andestimate charge weight/intensity and fracture lengths at steps 704 and720 of FIG. 7 (and also adjustments that can be made at steps 716 and734), multiple simulations may be run in order to achieve desiredfracture length and or to determine the required propellant weight etc.Appendix A provides an example of various simulation parameters andvalues also utilizing the PulsFrac™ software package for reference. Anydesired combination of simulation parameters may be adjusted to bothestimate and verify charge weights and intensity, fracture lengths,wellbore fluid levels, pressures, etc.

FIG. 17 illustrates a side view of two wells 1710, 1720 having parallelhorizontal wellbores 1714, 1724 prior to detonating a plurality ofcharges in the bottom wellbore 1724 to create a fracture networkaccording to an exemplary embodiment. Unlike FIG. 3 where the horizontalwellbores 304, 314, 324 were beside each other at a same depth, in theembodiment of FIG. 17 the first wellbore 1714 is above the secondwellbore 1724 at a different depth.

FIG. 17 illustrates the wells 1710, 1720 at a point in timecorresponding to just prior to detonating/the charges 502 at step 728 ofFIG. 7. At this point in time, fractures 1712 have already been createdextending from the first wellbore 1714 toward the second wellbore 1724.Likewise, a plurality of charges 502 separated by appropriate delayunits 504 have been set in the second wellbore 1724. In-well sensors 500are positioned in the first wellbore 1714 to detect changes in pressureand/or other characteristics within the first wellbore 1714 as a resultof detonating the charges 502 in the second wellbore. Surface sensors1700 are placed above ground in order to gather infor-mation of thesubterranean formation layers utilizing seismic vibrations caused bydetonating the charges 502 and creating a corresponding pressure pulsetrain as a result of each charge impulse in the pulse train beingseparated by an appropriate delay unit 504.

FIG. 18 illustrates the wells 1710, 1720 of FIG. 17 after the charges502 have been detonated. This point in time corresponds to sometimeafter step 728 of FIG. 7 has been performed. As illustrated in FIG. 18,new formed fractures 1722 extending upward from the second wellbore 1724interconnect with the previously existing fractures 1712 extendingdownward from the first wellbore 1714 In this way, an interconnectedfracture network 1716 is formed between the first wellbore 1714 and thesecond wellbore 1724.

FIG. 19 illustrates a plurality of vertical wellbores 1900, 1920, 1930having interconnected fracture networks 1906, 1916 therebetweenaccording to an exemplary embodiment. In addition to horizontal andvertical wellbores, sloping adjacent wellbores may also haveinterconnected fracture networks formed therebetween in a similar manneraccording to yet further embodiments.

FIG. 20 illustrates a plurality of horizontal wellbores 20, 22, 24, 26,28, 30, 32 in a gun barrel cylinder configuration, each wellbore havingfractures 50 radially orientated in all directions around the axlelength of the wellbores 20, 22, 24, 26, 28, 30, 32 according to anexemplary embodiment. The fractures 50 together create a largeinterconnected fracture network such that pressure changes within acenter wellbore 20 will cause associated pressure changes in all theother surrounding wellbores 22, 24, 26, 28, 30, 32. During theproduction phase, fluids or gases may be injected into the centerwellbore 20 and then production may simultaneously occur from all theother surrounding wellbores 22, 24, 26, 28, 30, 32. The drillingconfiguration of FIG. 20 may be particularly useful for thick shalefields and any number of additional interconnected horizontal wellboresmay be added as necessary to produce from the entire field.

According to various exemplary embodiments, multiple horizontalwellbores are drilled parallel to each other within an optimum distanceof each other (the optimum distance is usually 100-500 ft and can bedetermined using computer simulations). Propellants (liquid or solid orgas) and/or explosives (liquid or solid or gas) are then placed andignited in the wellbores. This results in high pressure pulse whichovercomes the rock tensile strength and drives cracks/fractures awayfrom the wellbore to establish multiple connections with adjacentwellbore(s). The ignition timing can be altered by placing short delaysalong the stimulation tool length to produce a resonant frequencydesigned to maximize rock breakdown and crack/fracture extension. Theresonant frequency ignition will also facilitate the creation “offplane” fractures (fracture growth in directions not perpendicular to theleast principal stress). Something which is difficult if not impossibleto do with traditional hydraulic fracturing techniques. The entirelength of the horizontal sections of the wellbore can be stimulated atone time or shorter sections may be stimulated sequentially.Instrumentation including but not limited to high speed pressurerecorders and seismic sensors can be placed in adjacent wellbore(s) torecord the event for subsequent analysis and optimization of theprocess. Seismic recording arrays may also be placed at surface toenhance analysis and improvement.

After the drilling and stimulation, the wellbore production is initiatedby producing hydrocarbons from some wellbores while simultaneouslyinjecting fluids or gases into others. The injection will maintainreservoir pressure and production rates. The fluid or gases injected(examples—methane, propane, carbon dioxide, water, etc.) will replacethe hydrocarbons as they are produced and can act as solvents to enhancemobility and ultimate production of reservoir hydrocarbons in place.

Multiple wellbores can be continuously added to the network over time.Single wellbores may use the same process by stimulating lengths of thewellbore and then isolating part of the stimulated length and injectioninto it while producing from other sections of the well.

Exemplary benefits of some embodiments include eliminating therequirement for hydraulic fracturing (and its common use of massivequantities of fracking fluids) and the potential for contaminatingground water with fracking fluids. Hydrocarbon reservoir utilization andefficiency may also be increased by multiple wellbores connected to eachother with a huge network of fractures to produce hydrocarbons andsimultaneously replace the produced volumes by injecting otherfluids/gases/solvents to maintain reservoir pressure and maximize totalproduction volumes.

According to some exemplary embodiments, multiple parallel wells withinterconnected fracture networks utilizing injection to enhanceproduction are combined with propellant/explosive stimulation techniquesto vastly increase the producing area (exposed shale face) therebyincreasing production, sweep efficiency and ultimate recovery.

In an exemplary embodiment, a method of recovering hydrocarbons from asubterranean formation includes drilling first and second adjacent wellsand detonating charges in each of the wells thereby causing fractures inthe subterranean formation to extend from each well and interconnectwith each other in a fracture network. The method further includesensuring that at least some of the first fractures interconnect with atleast some of the second fractures in the fracture network. Hydrocarbonsare then recovered from at least one of the first well and the secondwell. The charge detonations may include a plurality of chargesseparated by delay units to create a pulse train selected according to atype of subterranean formation. The pulse train may be detected bysensors to ensure the fracture network between the adjacent wellbores issufficiently interconnected. Fluids may be injected into injection wellsand while production is performed from interconnected production wells.

FIG. 25 illustrates a plurality of horizontal wellbores 20, 22, 24, 26,28, 30, 32 each having fractures 50 radially extending in all directionsaround the axle length of the wellbores 20, 22, 24, 26, 28, 30, 32 toform an interconnected fracture network taking advantage of permeabilityof the subterranean formation according to an exemplary embodiment. Theembodiment shown in FIG. 25 differs from the earlier embodimentillustrated in FIG. 20 by the wellbores 20, 22, 24, 26, 28, 30, 32 inFIG. 25 being further apart such that their fractures 50 do not directlyintersect with the fractures 50 of the adjacent wellbores 20, 22, 24,26, 28, 30, 32. However, despite the lack of direct intersection offractures 50 in FIG. 25, the fractures 50 still together create a largeinterconnected fracture network 250 by taking advantage of permeabilityof the subterranean formation 252. As such, it is to be understood thatthe term “interconnect” and derivates such as utilized in the phrase“interconnected fracture network” include cases where the fractures 50themselves do not directly intersect but are nonetheless interconnectedvia the permeability of the material of the subterranean formation.Fracture interconnection in this document generally refers to crosswellbore flow. Combinations of both directly connected (intersecting)fractures 50 and also fractures 50 that are close enough to establishsufficient cross wellbore flow may be utilized together. During step732, the primary concern in some embodiments may be testing forsufficient wellbore flow between adjacent wellbores 20, 22, 24, 26, 28,30, 32 in order to determine whether the fractures 50 are sufficientlyinterconnected.

FIG. 26 illustrates wellbore pressure changing over time during a timedignition according to an exemplary embodiment. Timed ignition (e.g.,millisecond delays) can be used for both (or either) seismic signalgeneration and for propellant burn control (to control burn pressure andburn time to produce best fracture length/pattern). By timing theignition of different sections 502 of propellant, well overpressure canbe avoided while at the same time the burn time can be extended therebyextending pressure time and fracture lengths. As shown by the pressureline 260 in FIG. 26, each burn ignition is in sequence and raises thepressure a bit more as time runs along the bottom axis of the graph. Asillustrated, the maximum pressure is about 14,000 psi at around the 150ms burn time. By having a plurality of propellant sections 502 ignitedin sequence, the total burn time may range in some embodiments from 100ms to 1000 ms. The pressure and burn times shown in FIG. 26 differ withwhat would happen in a typical propellant burn where all propellantsections 502 would be ignited at the same time. The graph for typicalsimultaneous ignition would have the pressure line 260 rapidly rise in ahighly sloped essentially straight line up to around 20,000 psi, whichrepresents an overpressure state where the pipe and/or other equipmentwithin the wellbore may be destroyed by such a rapid and high increasein pressure. Timed ignition as illustrated in FIG. 26 allows morepropellant to be put in the wellbore over a typical propellantapplication while avoiding overpressure situations. The timed ignitiontechnique is particular beneficial for creating interconnected fracturesas described above such as step 728 of FIG. 7; however, the sametechnique may also be applied in single wellbore applications.

FIG. 27 illustrates a plan view of two adjacent horizontal wellbores270, 272 having an angle A between their bore directions according to anexemplary embodiment. In order to test and determine the optimal spacingand other parameters for fracture 274 interconnection, two adjacentwell-bores 270, 272 such as illustrated in FIG. 27 may be drilled. Thewellbores 270, 272 have different bore directions differing by angle A.In this way, as the position along the wellbore length moves from aninitial position D0 to final position D9, the separation distancebetween the wellbores 270, 272 increases. At the initial positionsbetween D0 and D1, the fractures 274 are not very extensive becausethere is not enough space for the fractures 274 to expand in differentdirections and there is not much space in the subterranean formations.Therefore, reduced hydrocarbon flow rates may result from interconnectedfractures 274 this close to each other. Alternatively, in the range ofD3-D5, the fractures 274 have enough room to spread in differentdirections while still achieving good interconnection with the fractures274 from the adjacent wellbore 270, 272. Hydrocarbon flow rates in thissection may be maximized for these reasons. Likewise, in the ranges ofD7-D9, the fractures 274 are too far apart that there is very littlecross wellbore flow. The fractures in the range of D7-D9 are simply notsufficiently interconnected to achieve acceptable hydrocarbon flowrates.

To determine optimal wellbore spacing, production/injection tests may beperformed on the wellbores 270, 272. To this end, testing personnel maydrill test wellbores 270, 272 starting from known positions and with aknown angle A between them. Testing personnel may then perform fractureinterconnection tests in different distance ranges D1-D9 within theadjacent wellbores 270, 272 in order to determine the distance range(s)D1-D9 that have the best cross wellbore flow rates. For example, byisolating and testing fracture interconnection results and flow rateswithin different sections D0-D1, D2-D3, D3-D4, etc., it may bedetermined which distance section(s) is/are optimal in a givenenvironment. For example, assuming that hydrocarbon recovery rates areoptimal in the D4-D5 distance section, future wells at this site may bedrilled parallel to one another having a separation distance Dsepbetween them. The optimal separation distance Dsep is equivalent to thedistance between the first and second test wellbores 270, 272 at theD4-D5 distance sections.

Because the wellbores 270, 272 are straight lines with an angle betweenthem, there will be an intersection point. The intersection point may bean actual intersection such as an origin point at the initial positionD1 of each wellbore 270, 272, or the intersection point may be atheoretical intersection point where the wellbores 270, 272 wouldintersect if they were drilled back further. Dsep can be calculated bythe law of cosines because the distance of the sub-sections where theoptimal test results are achieved from the intersection point are knownand the angle between the wellbore lines is known. The test resultsshowing that the D4-D5 distance sections are at the optimal distanceDsep may also be utilized to update simulation parameters to help betterpredict future adjacent wells.

A benefit of having at least two wellbores 270, 272 diverging from eachother at an angle A is to perform fracture testing and flow rate testingat different wellbore distances without being required to drill separatewellbores at each distance. Instead, a fixed number of wellbores 270,272 are drilled diverging at angle A from one another, and tests aredone at different distances D0-D9 along those wellbores in order to testdifferent separation distances Dsep. As tests are conducted along thelengthwise distances D0-D9, eventually there will be no pressure signaldetected in one wellbore 270 as a result of pressure changes in theadjacent wellbore 272. At this point, the well-bores are too far awayand there is no longer sufficient interconnection of the fractures 274.

FIG. 28 illustrates a projection view of a plurality of a plurality ofadjacent horizontal wellbores 21, 23, 25, 27, 29, 31, 33 having an angleA between their bore directions according to an exemglary embodiment.This embodiment is similar to that shown in FIG. 27, except rather thanjust two adjacent wellbores 270, 272 utilized for testing, FIG. 28includes seven wellbores organized in a gun barrel cylinderconfiguration. The center wellbore 21 may be a straight-line wellboredrilled from a starting position D0 illustrated at the upper left-handcorner of FIG. 28. Each of the surrounding wellbores 23, 25, 27, 29, 31,33 may diverge from the center wellbore 21 by an angle of A. As such acone-shaped configuration of wellbores 21, 23, 25, 27, 29, 31, 33 isformed where the distance of any surrounding wellbore 23, 25, 27, 29,31, 33 gets further and further away from the center wellbore 21 as thedistance from the starting point D0 extends to D9.

As a result of the cone shaped configuration, not only can testingpersonnel empirically test to find the optimal wellbore separationdistance Dsep for maximum flow rates (as can be done in FIG. 28), thetesting personnel may also empirically determine what type of positionalspacing and orientation of wellbores 21, 23, 25, 27, 29, 31, 33maximizes cross wellbore flow rates. For instance, it may be determinedthat for wellbores that are vertically stacked (such as wellbore 23being over wellbore 21), maximum flow rates are achieved around the D3distance. The D3 distance can be utilized with the known angle A tocorrelate to a first optimal wellbore separation Dsepl at whichvertically stacked horizontal wellbores can be drilled to maximizeproduction. Likewise, the cone configuration of FIG. 28 may show thatfor horizontally adjacent wellbores (such as wellbore 33 being besidecenter wellbore 21), maximum flow rates are achieved around the distancerange D5 distance. Again, the D5 distance can be utilized along with theknown angle A in order to determine a second optimal wellbore separationdistance Dsep2 at which horizontally adjacent wellbores can be drilledto maximize production.

The cone shaped configuration of FIG. 28 also allows the field testingpersonnel to check for the effects of the natural formation stresses.For instance, certain subterranean formations may have naturally betterpermeability in certain directions or orientations. The cone shapedconfiguration of FIG. 28 has a plurality of wellbores 23, 25, 27, 29,31, 33 surrounding a center wellbore 21 and therefore many angles ofnatural stresses can be tested.

In an exemplary embodiment, recovering hydrocarbons from a subterraneanformation includes drilling first and second adjacent wells anddetonating charges in each thereby causing fractures in the subterraneanformation to extend from each well and interconnect in a fracturenetwork. The charge detonations may include charges separated by delayunits to create a pulse train at a resonant frequency of thesubterranean formation. Sensors may be positioned within one or more ofthe wellbores and the surface, and the pulse train may be detected bythe sensors to ensure the fracture network between the adjacentwellbores is sufficiently interconnected. The adjacent wells may beparallel to each other and separated by an optimal separation distancedetermined by testing different sections of test wellbores that divergefrom an intersection point at a known angle. The charges may bepropellant based. Fluids/gases may be injected into injection wells andproduction performed from interconnected production wells.

Although the invention has been described in connection with preferredembodiments, it should be understood that various modifications,additions and alterations may be made to the invention by one skilled inthe art without departing from the spirit and scope of the invention.For example, the above techniques may be applied to any combination ofhorizontal, vertical and sloping wells. Wellbores may be horizontal orhighly deviated. Although the injection well is preferred to besurrounded on other sides by production wells so that all fractures areutilized to provide pressure to other wells, this is not a strictrequirement and injection may also be performed utilizing an edge wellconnected on only one side rather than a centrally connected well.Additionally, both the injection wells and the production wells maycontain additional fractures that are not interconnected to any otheradjacent well. Having additional unconnected fractures may work tomaximize production.

Either propellants (solid or liquid or gas) and/or explosives (solid orliquid or gas) may be used as the charges 502. Wellbores may be linedwith casing (cemented in place or uncemented), may contain a slottedliner or may be open hole completions. Entire lengths of wellbores maybe stimulated simultaneously or small sections sequentially. Theignition can be a rapid continuous process such as when liquidpropellant is utilized or when a plurality of charge sections aresimultaneously detonated as a group, or may include a certain number ofmicro/millisecond/other delays intermediate separate charge sections toprovide desired pulse trains for sensor detection and/or to establishresonant frequencies designed to maximize: rock breakdown, creation ofoff plane fractures and fracture extension. In an exemplary embodiment,the charge delays are set to create a pulse train of detonations at theresonant frequency of the subterranean rock material surrounding thewellbore. Entire lengths of wellbores may produce and/or be injectedinto simultaneously or small sections can be activated andproduce/injected into sequentially. Single wellbores may use the sameprocess by stimulating lengths of the wellbore and then isolating partof the stimulated length and injection into it while producing from thearea that is not isolated. Multiple fluids and or gases can be used forinjection including but not restricted to: nitrogen, methane, propane,butane, carbon dioxide, methanol, water or any combination of theseand/or other fluids/gases.

It may be beneficial to place in-well sensors 500 in an existingwellbore to detect changes of pressure and/or other characteristics as aresult of detonating charges in an adjacent second wellbore; however,both the in-well sensors 500 and surface sensors 1700 are optional andmay be omitted in other embodiments.

Although parallel wellbores are preferred to create fracture networkbetween them, fracture network may also be created between wellboresthat are not parallel to each other. For instance, a horizontal wellboremay be adjacent a portion of a vertical wellbore and a fracture networkmay be created between these two non-parallel wellbores. The fracturesare not limited to being bi-wing fractures and can instead be created inany configuration extending outward at any angle from a wellbore. Thefractures may be limited in some configurations to only be directedtoward adjacent wells to maximize interconnection with fractures fromthose other wellbores, or fractures may be directed in any otherdirections from the wellbore.

Charge 502 detonation is beneficial for creating interconnectedfractures between wellbores because the charge detonation occurs fastenough that a plurality of fractures are created substantiallysimultaneously. There is little time for excess pressure to bleed offbefore additional fractures are created. For this reason, preferredembodiments employ charge sections 502 for creating interconnectedfracture networks 306, 316 between adjacent wellbores. In contrast, inhydraulic fracturing the fractures are created from a slower pressurebuild-up of pumped fracture fluid and therefore it is more difficult tocreate interconnected fracture networks using hydraulic fluid. However,it should be noted that in some embodiments of the invention,interconnected fractures and fracture networks may include fracturesthat were originally created utilizing hydraulic fracturing techniques.For example, an initial wellbore may first be fracked utilizinghydraulic fracturing methods and then an adjacent wellbore may beinterconnected therewith utilizing the propellant based techniquesdescribed herein. Fractures and interconnected fracture networks may becreated utilizing any desired process, and any combination ofhydraulically and charge based fractures may be employed in differentembodiments.

After drilling and stimulation, wellbore production may be performed byproducing hydrocarbons from some wellbores while simultaneouslyinjecting fluids or gases into others. This combinedinjection/production process is illustrated in FIG. 8. However, itshould be noted that the injection does not necessarily need to startimmediately with production. Instead, injection may be delayed byseveral weeks/months after the wells are drilled, and/or may be delayedby several weeks/months after production is started. For instance,regular production without fluid injection may immediately follow step738 of FIG. 7. Then, some period of time later, perhaps upon welldepletion becoming evident, the combined injection/production process ofFIG. 8 may begin at step 800.

In some embodiments, processing facilities are added at surface torefine the produced hydrocarbons to a burnable product, which isutilized to fuel electric generating equipment. Carbon dioxide may becaptured from the combustion and then injected back into the wells. Asthe volume of carbon dioxide will be greater than the volume of theproduced hydrocarbons, a small amount of the refined product can also beutilized as feedstock to produce plastics. In this way, the entireprocess is tied together and can result in a “carbon neutral” method ofproducing electricity.

Furthermore, although the above examples have focused on creating andproducing from multiple wellbores, the disclosed techniques formaximizing fracture length and creation efficiency may also be performedin a single wellbore. For instance, the resonant frequency stimulationprocess may be utilized to stimulate a single wellbore and then injectinto one part of the single wellbore while producing from another of thesingle wellbore.

The computer simulations illustrated in FIGS. 9-13 and 21 and utilizedto estimate charge intensity and time delays at steps 704 and 720 ofFIG. 7 may be implemented by software executed by one or more processorsoperating pursuant to instructions stored on a tangiblecomputer-readable medium such as a storage device. Examples of thetangible computer-readable medium include optical media (e.g., CD-ROM,DVD discs), magnetic media (e.g., hard drives, diskettes), and otherelectronically readable media such as flash storage devices and memorydevices (e.g., RAM, ROM). The computer-readable medium may be local tothe computer executing the instructions, or may be remote to thiscomputer such as when coupled to the computer via a computer networksuch as the Internet. The processors may be included in ageneral-purpose or specific-purpose computer or computer server thatbecomes the simulation program or any of the above-describedfunctionality as a result of executing the instructions. In addition toa dedicated physical computing device, the word “server” may also mean aservice daemon on a single computer, virtual computer, or sharedphysical computer or computers, for example.

In other embodiments, rather than being software modules executed by oneor more processors, the above-described simulation functionality may beimplemented as hardware modules configured to perform theabove-described functions. Examples of hardware modules includecombinations of logic gates, integrated circuits, field programmablegate arrays, and application specific integrated circuits, and otheranalog and digital circuit designs.

The term “charge” and related derivatives such as “charges”, “chargesection”, “charge blasts”, etc. are intended in this description toencompass both propellant and high explosives. Upon ignition, propellantdeflagrates in a rapid burn whereas high explosive detonates in anexplosion. As such, the term “detonation” and its related derivativessuch as “detonating”, “detonate”, etc. as utilized herein are intendedto encompass both deflagration of propellant and detonation of highexplosives.

Regarding the term bi-wing fractures, this term is utilized herein toinclude hydraulic and propellant driven fractures. For instance, bi-wingas utilized herein can refer to both hydraulic fractures as well asmultiple radial fractures that are propellant driven.

Functions of single elements described above may be separated intomultiple units, or the functions of multiple elements may be combinedinto a single unit. All combinations and permutations of the abovedescribed features and embodiments may be utilized in conjunction withthe invention.

1. A method of recovering hydrocarbons from a subterranean formation,the method comprising: drilling a first well; drilling a second welladjacent to the first well; detonating a first charge in the first wellthereby causing first fractures in the subterranean formation to extendfrom the first well toward the second well; detonating a second chargein the second well thereby causing second fractures in the subterraneanformation to extend from the second well toward the first well; ensuringvia a sensor coupled to at least one of the first well and the secondwell that a degree of interconnectivity between the first fractures andthe second fractures is above a threshold value; and recoveringhydrocarbons from at least one of the first well and the second well. 2.(canceled)
 3. The method of claim 1, wherein the second well is drilledsubstantially parallel to the first well, the method further comprisingseparating the first well and the second well from one another by aseparation distance determined by: drilling a first test well extendingin a first direction; drilling a second test well extending in a seconddirection, the second direction having an angle difference with thefirst direction such that the first test well and the second testincrease in distance from one another as they extend away from anintersection point; detonating a first test charge in the first wellthereby causing first test fractures in the subterranean formation toextend from the first test well toward the second test well; detonatinga second test charge in the second test well thereby causing second testfractures in the subterranean formation to extend from the second testwell toward the first test well; performing a plurality of tests togauge fracture interconnection levels between the first test well andthe second test well in a corresponding plurality of sections of atleast one of the first test well and the second test well; determiningan optimal one of the sections that has an optimal fractureinterconnection level by comparing results of the tests for theplurality of sections; and determining the separation distance accordingto a distance the optimal one of the sections is from the intersectionpoint and the angle between the first direction and the seconddirection.
 4. The method of claim 1, further comprising forming at leastone of the first charge and the second charge as a plurality of chargesections coupled in series with a respective delay unit interspacedtherebetween, wherein each delay unit provides a detonation delaybetween each of the charge sections.
 5. (canceled)
 6. The method ofclaim 4, further comprising setting the detonation delay to form adetonation pulse train at a resonance frequency of the subterraneanformation.
 7. The method of claim 4, wherein a total number of chargesections coupled in series is at least ten.
 8. The method of claim 4,wherein the detonation delay of each respective delay unit is a samevalue in a range from one-tenth milliseconds to ten milliseconds.
 9. Themethod of claim 4, further comprising analysing the subterraneanformation according to a plurality of data received from a plurality ofsurface sensors measuring a plurality of successive ignition impulsesformed by detonation of the charge sections.
 10. The method of claim 9,wherein analysing the subterranean formation comprises generating athree-dimensional map of subterranean formation according to the datareceived from the surface sensors.
 11. The method of claim 9, furthercomprising ensuring that at least some of the first fracturesinterconnect with at least some of the second fractures according to thedata received from the surface sensors.
 12. The method of claim 1,further comprising: drilling the first well with a first horizontalsection; drilling the second well with a second horizontal sectionadjacent to the first horizontal section; ensuring the first fracturesand second fractures extend toward each between the first horizontalsection and the second horizontal section.
 13. The method of claim 1,further comprising selecting burn intensities of the first charge andthe second charge in advance utilizing a computer simulation processdesigned to achieve a desired amount of interconnection between thefirst fractures and the second fractures given a plurality of knownparameters of the subterranean formation.
 14. The method of claim 13,further comprising: measuring an actual amount of interconnectionbetween the first fractures and the second fractures after detonatingthe first charge and the second charge; and updating the knownparameters of the subterranean formation according to differencesbetween the desired amount of interconnection and the actual amount ofinterconnection.
 15. The method of claim 1, further comprising, afterensuring that at least some of the first fractures interconnect with atleast some of the second fractures, injecting material into the secondwell while recovering hydrocarbons from the first well.
 16. The methodof claim 15, further comprising: drilling a third well adjacent to thesecond well; detonating a third charge in the third well thereby causingthird fractures in the subterranean formation to extend from the thirdwell toward the second well; ensuring that at least some of the thirdfractures interconnect with at least some of the second fractures; andsimultaneously recovering hydrocarbons from the first well and thesecond well while injecting a material into the second well. 17.(canceled)
 18. The method of claim 1, further comprising: placing aplurality of in-well sensors within the first well prior to detonatingthe second charge in the second well; and ensuring that at least some ofthe first fractures interconnect with at least some of the secondfractures according to data received from the in-well sensors inresponse to detonating the second charge in the second well.
 19. Themethod of claim 1, wherein the sensor is one of a plurality of in-wellinclude pressure sensors for measuring pressure changes in the firstwell resulting from detonating the second charge in the second well. 20.The method of claim 1, wherein the sensor is one of a plurality ofin-well seismic sensors for measuring vibrations detected in the firstwell resulting from detonating the second charge in the second well.21-22. (canceled)
 23. The method of claim 1, wherein at least one of thefirst charge and the second charge are propellant charges.
 24. Themethod of claim 1, further comprising drilling a plurality of additionalwells such that the first well and the second well in combination withthe additional wells form a gun barrel cylinder configuration having acenter wellbore with a plurality of surrounding wellbores runningplurality.
 25. (canceled)
 26. The method of claim 1, further comprisingensuring that a cross wellbore flow rate achieved between the first welland the second well is greater than a predetermined threshold.